Method for single-stage treatment of siliceous subterranean formations

ABSTRACT

In a method of treating a sandstone-containing formation penetrated by a wellbore, a treatment fluid comprising an aqueous fluid containing a Bronsted acid, a hydrogen fluoride source and an organic acid or salt thereof that is substantially soluble in the aqueous fluid is formed. The treatment fluid contains less than about 2% of fluoride (F−) by weight of the fluid and from 2% or less of sodium (Na+) by weight of the fluid. The treatment fluid is introduced into the formation through the wellbore as a single-stage without introducing an acid-containing fluid preflush into the formation prior to introducing the treatment fluid.

CROSS REFERENCE TO RELATED APPLICATION

This application is a Continuation-In-Part of and also claims thebenefit of United States Non-provisional application Ser. No.12/019,394, filed Jan. 24, 2008.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.Various methods may be used to enhance the productivity of fluids fromwells formed in subterranean formation, such as hydrocarbon-producingwells that produce oil or gas. Different characteristics or propertiesof the wells may limit the production of fluids. These may includeinsufficient flow paths in the formation, wellbore coatings andnear-wellbore formation damage resulting from prior treatments oroperations, such as from drilling fluids and the like, that limit fluidflow.

One method of treating such wells to enhance production involves the useof acids or acid-based fluids for dissolving portions of the formationto create alternate flow paths and for removing wellbore coatings andnear-wellbore formation damage. Such acids or acid-based fluids areuseful for this purpose due to their ability to dissolve both formationminerals and contaminants, such as those that were introduced into thewellbore/formation during drilling or remedial operations and which maycoat the wellbore or have penetrated the formation. In the case oftreatments within the formation, rather than wellbore treatments, theportion of the formation that is near the wellbore and that firstcontacts the acid is usually adequately treated. Portions of theformation further from the wellbore, however, may remain untreated bythe acid, due to the acid reacting before it can penetrate very far fromthe wellbore.

Carbonate formations and materials are well suited for treatment withacids because they readily dissolve in a variety of different acids.Sandstone or siliceous formations or materials, however, are onlysusceptible to dissolution in hydrofluoric (HF) acid. Thus, sandstoneformations are often treated with a mixture of hydrofluoric andhydrochloric acids (called mud acid). This acid mixture is oftenselected because it will dissolve clays (found in drilling mud) as wellas the primary constituents of naturally occurring sandstones (e.g.,silica, feldspar, and calcareous material). Such treatments may becarried out at low injection rates to avoid fracturing the formation.

A major problem with sandstone acidizing as presently practiced is thatmultiple stages are required to prevent deleterious reactions betweencomponents of the formation or dissolved materials and the acidizingfluids. Of particular concern is contact between dissolved calcium ionsand fluoride ions that can produce a solid fluorite (CaF₂) that canpartially negate the effectiveness of the treatment.

Chelating agents can be used to keep calcium and other metal ions insolution to prevent precipitation of these solid compounds. Thechelating agents may have limited solubility, however, in low pH fluids.This presents a particular problem as a higher pH may make the acidizingfluid less effective.

Because of these problems, several stages of fluids are typicallyrequired in acid treatment of sandstone formations. These stagesinclude 1) a brine stage (e.g. KCl or NH₄Cl) to displace incompatiblecations, such as Ca²⁺ and Na⁺ ions, away from the wellbore; 2) an acidstage (e.g. HCl, organic acid, etc.) to dissolve or remove the calciumor magnesium carbonate in the zone to prevent precipitation of CaF₂; 3)a primary silicate dissolution stage (e.g. HF+HCl or an organic acid) toremove alumino-silicates; and 4) a final brine stage to displace thedissolved ions and spent acids away from the critical matrix. FIG. 1illustrates a prior art multiple stage treatment. In particular, thecalcium removal stage and the silicate dissolution stages both alter thepermeability of the matrix and thus affect the injection of subsequentfluids.

Because placement and proper diversion facilitate successful treatmentof the formation, having multiple stages may make optimal placementdifficult, as each stage may ultimately be positioned differently. Whatis therefore needed is a means for effectively treating sandstone orsiliceous formations or materials with acid or acid-based solutions thatreduces the amount of precipitates formed, in particular CaF₂precipitates, and that eliminates the need for multiple steps andtreatments, which can result in improper placement and inadequatetreatment.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, and theadvantages thereof, reference is now made to the following descriptionstaken in conjunction with the accompanying figures, in which:

FIG. 1 is a schematic illustrating a prior art multiple stage sandstoneacidizing treatment;

FIG. 2 shows a plot of the metal ion concentration over time of acalcite/kaolin mineral treated with a treatment solution (Sample A) fromExample 1 at 125° C.;

FIG. 3 shows a plot of the metal ion concentration over time of acalcite mineral treated with a treatment solution using citric acid(Sample B) from Example 2 at 65° C.;

FIG. 4 shows the final Ca and Al ion concentration for Samples A-C,wherein Sample C has a different DAE/ammonium bifluoride concentrationfrom that of Sample A;

FIG. 5 shows the final concentration of various precipitates for variouschelating agents used in mud-acid treatment fluids in treating calcite;

FIG. 6 shows the concentration of various metals during treatment of aBerea core sample for 9/1 mud acid containing monosodium HEDTA; and

FIG. 7 shows the concentration of various metals during treatment of aBerea core sample for a DAE and ammonium bifluoride treatment fluid.

SUMMARY

In a method of treating a sandstone-containing formation penetrated by awellbore, a treatment fluid comprising an aqueous fluid containing aBronsted acid, a hydrogen fluoride source and an organic acid or saltthereof that is substantially soluble in the aqueous fluid is formed.The treatment fluid contains less than about 2% of fluoride (F⁻) byweight of the fluid and from 2% or less of sodium (Na⁺) by weight of thefluid. The treatment fluid is introduced into the formation through thewellbore as a single-stage without introducing an acid-containing orbrine-containing fluid preflush into the formation prior to introducingthe treatment fluid.

In certain embodiments, the combination of the Bronsted acid and organicacid or salt thereof may be present in the treatment fluid in an amountsufficient to keep at least 5000 ppm Ca²⁺ in solution. The organic acidor salt thereof may be present in an amount of from about 5 to about 40%by weight of the treatment fluid and may be an ammoniated chelate.

In some embodiments, the treatment fluid may have a pH of about 3 orless and may be used at a temperature of from about 200° C., about 150°C., about 100° C., about 80° C. or less.

In some embodiments, to enhance the treatment, the treatment fluid maybe shut-in the formation for several hours prior to flowing back thetreatment fluid to the surface. While any suitable shut-in time may beused, some preferred periods are from about 2 hours to about 24 hours aswell as any point along the continuum therebetween, and more preferablyfrom about 3 hours to about 12 hours as well as any point along thecontinuum therebetween.

DETAILED DESCRIPTION

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

The description and examples are presented solely for the purpose ofillustrating the preferred embodiments of the invention and should notbe construed as a limitation to the scope and applicability of theinvention. While the compositions of the present invention are describedherein as comprising certain materials, it should be understood that thecomposition could optionally comprise two or more chemically differentmaterials. In addition, the composition can also comprise somecomponents other than the ones already cited. In the summary of theinvention and this detailed description, each numerical value should beread once as modified by the term “about” (unless already expressly somodified), and then read again as not so modified unless otherwiseindicated in context. Also, in the summary of the invention and thisdetailed description, it should be understood that a concentration rangelisted or described as being useful, suitable, or the like, is intendedthat any and every concentration within the range, including the endpoints, is to be considered as having been stated. For example, “a rangeof from 1 to 10” is to be read as indicating each and every possiblenumber along the continuum between about 1 and about 10. Thus, even ifspecific data points within the range, or even no data points within therange, are explicitly identified or refer to only a few specific, it isto be understood that inventors appreciate and understand that any andall data points within the range are to be considered to have beenspecified, and that inventors possession of the entire range and allpoints within the range.

In the present invention, by providing a precise balance of components,a method of treating sandstone or siliceous formations may beeffectively carried out in a single-stage. The single-state treatmentsovercome the limitations of prior art treatments that require multiplestages because the different stages are not always consistently placed.Thus, one stage may locate in one portion of the matrix and anotherstage may locate in a different portion of the matrix. As a result, thematrix may not receive sufficient volumes of each fluid stage foreffective treatment.

The treatment fluid used in the method is formed from an aqueous fluidcontaining a combination of a hydrogen fluoride source, a proton donoror Bronsted acid and an organic acid or salt thereof that may act as achelating agent that has substantial solubility in the Bronsted acidsolution. As used herein, a Bronsted acid is any compound having theformula AH=A⁻+H⁺ when added to water. By the careful selection of thesecomponents, the calcium- and silicate-dissolving fluids may be combinedin a single stage to dissolve both calcium carbonate as well assiliceous materials. These may include the aluminosilicates, such asclay, feldspar and formation fines. This allows the brine stages thatare typically used in acid treating of wells of sandstone formations tobe eliminated.

Depending upon the temperatures of use different treatment fluids may beused. In some cases, for downhole temperatures of from about 100° C. toabout 200° C., the treatment fluid may make use of ammoniated chelatingagents that have high solubility at low pH or at a pH of about 4 orabove, and facilitate maintaining calcium ions (Ca²⁺) in solution. Theammoniated chelants may include certain aminopolycarboxylate andpolyaminopolycarboxylate compounds that have substantial solubility inaqueous fluids having a pH of about 4 or more under the conditions ofuse. In particular, these may include the ammonium salts of thesecompounds. The ammonium salts of di-, tri- andtetra-aminopolycarboxylates are particularly useful in the presentinvention. The ammonium salts of these compounds exhibit highersolubilities at low pH than do their acid counterparts, particularly atlower temperatures. Examples of suitable organic acids or organic acidsalts of the present invention are free-acids or partial-ammonium saltsof ethylenediamine tetraacetic acid (EDTA), hydroxyethyl ethylenediaminetriacetic acid (HEDTA), diethylene triamine pentaacetic acid (DTPA) and2-hydroxyethyl iminodiacetic acid (HEIDA).

At lower temperatures of 125° C. or less, there is typically not enoughreactivity to adequately dissolve the formation matrix at pH's higherthan above about 3. At these temperatures, the treating fluid isformulated as a mud acid in combination with an organic acid or saltthereof that may act as a chelating agent and that is soluble in the mudacid solution. This allows a lower pH of from about 4 or less, moreparticularly, from about 3 or less, to be used. This allows the use ofmore aggressive HF acids to be used, particularly at lower temperatures.At lower temperatures of about 125° C., about 100° C., about 90° C., oreven about 80° C. or less, the treating fluid formulated at the higherpH from about 4, about 5, about 6 or more may also be used in treatingformations in matrix acidizing. Despite the lower reactivity, thehigher-pH formulations may effectively dissolve some damaging mineralsat lower temperatures. As such, these formulations have the ability tostimulate the permeability of formations damaged by those minerals.

The mud acid may be a mixture of hydrofluoric acid or hydrofluoric acidsource and hydrochloric acid or an organic acid. This may includemixtures of different acids. Such mixtures or solutions employinghydrofluoric acid and at least one other acid are commonly referred toas “mud acids” and are well known to those skilled in the art. Thenon-HF acids used may include, but are not limited to, hydrochloricacid, hydroiodic acid, hydrobromic acid, sulfuric acid, sulfamic acid,phosphoric acid, formic acid, acetic acid, halogenated derivatives ofacetic acid, citric acid, propionic acid, tartaric acid, lactic acid,glycolic acid, aminopolycarboxylic acids, sulfamic acid, methanesulfonicacid, malic acid, maleic acid, succinic acid, oxalic acid,methylsulfamic acid, chloroacetic acid, 3-hydroxypropionic acid,polyaminopolycarboxylic acid, polycarboxylates such as poly(acrylicacid), poly(maleic acid) and their copolymers, bisulfate salts andcombinations of these. In mud acids, the HF may be present in thetreatment fluid in an amount to provide less than 2% by weight offluoride. The other acid, such as HCl, may be present in the aqueoussolution in an amount of from about 3 to about 25% by weight of thesolution.

In such low pH or mud acid treatment solutions, the acid soluble organicacids or organic acid salts may include ethylenediamine tetraacetic acid(EDTA), hydroxyethyl ethylenediamine triacetic acid (HEDTA), diethylenetriamine pentaacetic acid (DTPA), 2-hydroxyethyl iminodiacetic acid(HEIDA), citric acid, tartaric acid, succinic acid, lactic acid, oxalicacid, malic acid and maleic acid, polycarboxylates, homopolymers orcopolymers of poly(acrylic acid) and poly(maleic acid) and thepartial-ammonium or sodium salts thereof.

Examples of various chelating agents and treatment solutions that mayhave applicability to the single-stage treatment of sandstone formationsinclude those described in U.S. Pat. Nos. 6,924,255 and 7,192,908, whichis herein incorporated by reference in its entirety for all purposes.

In both non-mud-acid and mud-acid treatment fluids, the chelating agentmay have a sufficient solubility in the treatment fluid to keep at leastabout 5000 ppm calcium ions in solution, more particularly at leastabout 10,000 ppm calcium ions, and still more particularly at leastabout 20,000 ppm calcium ions in solution.

It should be noted that the description and examples are presentedherein solely for the purpose of illustrating the preferred embodimentsof the invention and should not be construed as a limitation to thescope and applicability of the invention. While the compositions of thepresent invention are described herein as comprising certain materials,it should be understood that the composition could optionally comprisetwo or more chemically different materials. In addition, the compositioncan also comprise some components other than the ones already cited. Inthe description, each numerical value should be read once as modified bythe term “about” (unless already expressly so modified), and then readagain as not so modified unless otherwise indicated in context. Also, inthe description, it should be understood that a concentration or valuelisted or described as being useful, suitable, or the like, is intendedthat any and every concentration or value within the range, includingthe end points, is to be considered as having been stated. For example,“a range of from 1 to 10” is to be read as indicating each and everypossible number along the continuum between about 1 and about 10. Thus,even if specific data points within the range, or even no data pointswithin the range, are explicitly identified or refer to only a fewspecific, it is to be understood that the inventors appreciate andunderstand that any and all data points within the range are to beconsidered to have been specified, and that the inventors are inpossession of the entire range and all points within the range.

The chelating agent may be used in an amount of from about 5% to about40% by weight of the treating fluid. In certain embodiments, the amountof the chelating source may be from about 15% to about 30% by weight ofthe treating fluid, and more particularly, from about 20% to about 25%by weight of the treating fluid. These amounts may vary depending uponthe amount of Ca²⁺ that is kept in solution.

The hydrofluoric acid (HF) used in the treatment fluid may behydrofluoric acid itself or may be selected from a hydrofluoric acidsource, such as an ammonium fluoride salt, for example, ammoniumfluoride and/or ammonium bifluoride or mixtures of these. The HF sourcemay also be one or more of polyvinylammonium fluoride,polyvinylpyridinium fluoride, pyridinium fluoride, imidazolium fluoride,sodium tetrafluoroborate, ammonium tetrafluoroborate, salts ofhexafluoroantimony, TEFLON® synthetic resinous fluorine-containingpolymer, and mixtures of these. The hydrofluoric acid source must bewater soluble.

The amount of the hydrofluoric acid source used should provide less thanabout 2% fluorine (F⁻) by weight of the treatment fluid, including anyfluorine in the treatment fluid that may be provided in solution fromother fluorine sources. In certain embodiments, the fluorine may bepresent in an amount of 1.5% or 1% or less by weight of the treatmentfluid. This low amount of fluorine facilitates limitation ofprecipitation of CaF₂.

The amount of sodium (Na⁺) from any sodium source should also be limitedwithin the treatment fluid to about 2% or less by weight of thetreatment. In certain embodiments, the amount of sodium may be fromabout 1.5% or 1% or less by weight of the treatment fluid. Limiting theamount of sodium ions controls the precipitation of sodium fluoride(NaF).

In the treatment fluids of the invention, a Bronsted acid or protondonor is used. The Bronsted acid, as described previously, is anycompound having the formula AH═A⁻+H⁺ when added to water. This materialprovides fines stability. Various acids may be used. These may includeHCl, HF, organic acids, sulfamic acid, sulfonic acid, phosphonic acid,phosphoric acid, an ammonium salt, an ammine salt, a chelate acid andcombinations thereof. Those Bronsted acids that provide ammonium ionsmay be particularly useful in many applications. Typically, the Bronstedacid will be present in the treatment fluid in an amount of from about2% to about 20% by weight of the treatment fluid. The Bronsted acid maybe used in an amount to provide or adjust the treatment fluid to thedesired pH level. If the Bronsted acid is HF, the HF should provide nomore than 2% by weight of any fluoride.

Other additives or components may be used with the treatment fluid.Corrosion inhibitors may also be added to the treatment fluids.Conventional corrosion inhibitors may be used as long as they arecompatible with chemicals present in, or generated during use by, thetreatment fluid. Those compounds containing ammonium quaternary moietiesand sulfur compounds may be suitable (see for example U.S. Pat. No.6,521,028) for this purpose.

Friction reducers, clay control additives, wetting agents, fluid lossadditives, emulsifiers, agents to prevent the formation of emulsions,foaming agents, scale inhibitors, fibers, breakers and consolidatingmaterials may also be used in the treatment fluid. It is to beunderstood that whenever any additives are included, laboratory testsmay be performed to ensure that the additives do not affect theperformance of the fluid.

In treating the formation or well to create flow paths in the formationor to remove wellbore coatings and near-wellbore formation damage, thetreatment fluid with the hydrofluoric acid or HF source, Bronsted acidand chelating agent is introduced into the formation through thewellbore. Depending upon the formation temperature, which may range fromabout 200° C. or less, different treatment fluids may be used. Fortemperatures of from about 100° C. to about 200° C., the non-mud-acidtreatment fluid employing the free acid form or ammonium or sodium saltof chelating agents in solution with an HF-source may be used with pH'sof 4 or more. For lower temperatures of about 125° C. or less, themud-acid formulations with a pH of from about 4 or 3 or less may beused. The well may then shut in to facilitate dissolution of theformation materials or well damage.

In certain applications, diversion of the treatment fluid may benecessary. When reservoirs with different zones of permeability aretreated with the acid, the acid may flow into the high permeabilityzones and not stimulate the low permeability zones. To treat the lowpermeability zones, it may be necessary to divert the treatment fluidfrom high to low permeability zones. Diversion may be facilitated by anumber of techniques. These may include the use of ball sealers or otherdiversion materials. Particulate materials that are subsequentlyremovable, such as by dissolution and the like, may also be used.Examples of such particulates include rock salt, benzoic acid,oil-soluble-resin, etc. These materials may be introduced into theformation through the wellbore prior to introduction of the acidtreatment fluid or with the treatment fluid itself. When the diversionmaterials are used with the treatment fluid, the fluid is pumped at arate to penetrate the matrix of the rock without producing fractureswhere the fluid would be lost.

Diversion may also be achieved through the use of viscosified fluids.Such viscosified fluids may be those aqueous fluids that are thickenedor gelled through the use of polymers or viscoelastic surfactants (VES)typically used in fracturing, frac-packing and gravel packing and thelike. Such fluids are well known in the art. The VES may be selectedfrom the group consisting of cationic, anionic, zwitterionic,amphoteric, nonionic and combinations thereof. Some non-limitingexamples are those cited in U.S. Pat. Nos. 6,435,277 (Qu et al.) and6,703,352 (Dahayanake et al.), each of which are incorporated herein byreference.

Foamed or energized fluids may also be used for diversion. These may bethe thickened or gelled fluids previously described or other aqueousfluid. The foaming agent may include air, nitrogen or carbon dioxide.See, for example, U.S. Pat. No. 3,937,283 (Blauer et al.), incorporatedherein by reference. Foaming aids in the form of surfactants orsurfactant blends may be incorporated in the foamed fluid.

In certain applications, the treatment fluid may also be incorporatedinto a self-diverting fluid. Viscoelastic surfactants have been used ata low concentration that does not generate significantly increasedviscosity in such applications and have been disclosed, for instance, inU.S. Pat. No. 7,299,870, which is herein incorporated by reference. Bythe addition of the treatment fluid components, in similar quantities tothose previously described, into such VES fluids a self-diverting acidtreatment fluid or viscoelastic diverting acid (VDA) may be formed.

The follow examples serve to further illustrate the invention.

EXAMPLES Example 1

Slurry reactor tests were conducted on mineral solids composed of 20 gof calcite and 50 g kaolin. The minerals were crushed in a plastic bag,and then ground to a fine powder using a mortar and pestle. Thesemineral samples were then treated using a slurry reactor, available fromParr Instrument Company, Moline, Ill., which includes a 4500 series Parrpressure reactor with a capacity of 1 L of fluid. In each test, thefluid in the reactor was stirred at 100 rpm using a 4 bladed impellerdriven by a magnetic drive-coupled electric motor. The cell was fittedwith a 4″ dip tube to enable the acquisition of samples on a timedbasis. The cell was also fitted with a backpressure regulator, which wasset at 200 psi (1380 kPa). The reactor cell and internal parts wereconstructed of Hastelloy B. The solid mineral was placed into a Tefloncup which was fitted to the inside of the reactor cell. The cell wasthen sealed and heated to the desired reaction temperature. Separately,the treatment fluid solution was pumped into an accumulator housing andwas heated separately to the desired temperature. When both chamberswere at the test temperature, the test fluid was transferred to thechamber containing the stirred clay (at 100 rpm) and the test time wasstarted. The tests were typically carried out for 4 hours. Fluid sampleswere collected at targeted intervals throughout the experiment, werefiltered through 0.2 μm filters, and were diluted with deionized waterfor ICP analysis. The concentrations of dissolved aluminum and calciumresulting from efficient clay/carbonate dissolution were measured ineach of those samples using a Perkin-Elmer Optima 2000 DV inductivelycoupled plasma (ICP) optical emission spectrometry instrument. Theresidual solids at the end of the experiment were rinsed, filtered, andanalyzed using a Rigaku Miniflex X-ray Diffractometer (XRD). Theresulting XRD spectra were qualitatively compared to a library ofstandards using the Jade software package (Rigaku) to determine thereaction byproducts. The treatment fluid had a pH of about 4.5 and wascomposed of diammonium ethylenediamine tetraacetic acid (DAE) at 50 wt %(received as 45% active) and 1 wt % of ammonium bifluoride (Sample A).FIG. 2 shows the concentration of the metal ions for Al, Si and Ca overtime, as determined by ICP analysis. The treatment fluid Sample Adissolved a large amount of calcium and clay (as indicated by [Al]) butdid not precipitate CaF₂, as determined by X-ray diffraction (XRD). XRDanalysis showed the presence of calcium silicate, but no calcite orfluorite.

Example 2 Comparative

Slurry reactor tests were conducted on mineral solids composed of 70 gof calcite, as in Example 1. The minerals were treated at 65° C. with620 g of an aqueous treatment fluid (Sample B). The treatment fluidSample B was composed of 13 wt % citric acid, 4 wt % HCl, 5 wt %ammonium bifluoride and 2.5 wt % boric acid. The pH of Sample B was lessthan 3. FIG. 3 shows the calcium ion concentration for Sample B, asdetermined by ICP analysis, showing that the calcium concentration dropseven in the absence of clay. This indicates that citric acid is not agood solvent for calcium carbonate compared with DAE, as in Example 1.

Example 3

Three tests using Sample A, Sample B and a solution of 25 wt. % DAE(received as 45% active) with 1 wt. % ammonium bifluoride (Sample C).These three fluids were used in the slurry reactor consisting ofmixtures of kaolinite and calcite at 100° C. The maximum capacities forthe fluids to dissolve the clay and calcite were determined from thefinal concentration of Al and Ca in solution after a 6 hour test. FIG. 4is a summary of test results using Samples A-C. These are based onCaCO₃/kaolinite tests at 125° C. They show that all three formulationsdissolved clay (See Al conc.) but the DAE and ammonium bifluoridesolutions (Samples A and C) dissolved much more calcite.

Example 4

Mud acid treatment fluids were prepared with a 9/1 mud acid composed of9 wt % HCl and 1 wt % HF that was formed adding ammonium bifluoride. Themud acid treatment fluids had a pH<1. Various amounts of chelatingagents (˜8-20% (w/w), as shown in FIG. 5) were added to the mud acidformulation to try to suppress the formation of CaF₂. This testing wascarried out as a series of shaker-bath tests, modified from theexperimental procedures used in Examples 1-3. In the shaker bath tests,a water bath with a tray subjected to shaken-agitation was set toslightly above the set reaction temperature. In separate 150 mL plasticcontainers, 10 grams calcium carbonate was combined with 68 grams of thecandidate fluid and was subjected to heated agitation for a period of 4hours. The test consisted of completely spending the formulation oncalcite at 180° F. (82.2° C.). In all cases, the amount of liquid in theformulation was reduced by the amount of the chelate added so as to notdilute the acid. FIG. 5 shows the results. The wide bar is theconcentration of Ca in solution and the narrow bar is the amount ofsolids formed and the identification. The only chelate to completelysuppress formation of CaF₂ was monosodium HEDTA added at 8.8 wt %monosodium HEDTA. All of the other formulations gave some precipitationof CaF₂ or did not dissolve all of the calcite.

Example 5

The treatment fluid of 9/1 mud acid+8.8 wt % of monosodium HEDTAchelating agent from Example 4 was used to treat Berea core samples at250° F. (121.1° C.). The results are presented in FIG. 6. Thesecoreflood experiments used Berea sandstone cores (1″ (2.54 cm) diameter)in a Formation Response Tester Instrument. The cores were tested at 250°F. (121.1° C.) under a confining pressure of 2000 psi (13,780 kPa) in aViton sleeve. A backpressure of 500 psi (3,447 kPa) was used to keep CO₂in solution, allowing accurate measurement of the differential pressure(top to bottom) across the core. After the brine-saturated core hasreached temperature, the initial permeability to 5% NH₄Cl brine (k-ini)was measured separately in the production and injection directions fromthe differential pressure that is measured across the core [ΔP(ini)] byDarcy's law, familiar to those skilled in the art. In each test, 70 porevolumes (PV) of treatment fluid were subsequently pumped through thecore in the downward injection at 5 mL/min (“injection direction”).During the treatment stage, samples of the effluent during injection ofeach pore-volume were collected and were later analyzed usinginductively-coupled plasma (ICP) optical emission spectrometry.Following the treatment stage, the return permeability to 5% NH₄Cl wasmeasured in the production and injection directions to determine thefinal permeability (k_(fin)) In both cases the concentrations of theeffluents were plotted versus # of injected pore-volumes and the insetbox of FIG. 6 shows the cumulative (mg) of metal removed. In the case ofthe solution of 9/1 Mud Acid+8.8% monosodium HEDTA, the core treatmentled to a permeability ratio (k-fin/k-ini, shown in FIG. 6 as 81/62) of131%, a 31% stimulation of the core permeability. The ICP trace in FIG.6 indicates first rapid generation of dissolved calcium, which would notoccur in the case of fluorite precipitation. Additionally, the highconcentrations of aluminum and silicon indicate efficientaluminosilicate dissolution under these experimental conditions.

Example 6

A treatment fluid containing 50% by weight of DAE (45% active) and 1% byweight ammonium bifluoride (ABF) was used to treat Berea core sample at250° F. (121.1° C.). This fluid stimulated the core and removedsignificant amounts of Ca and Al. The results are presented in FIG. 7.In that data, a high calcium concentration is initially achieved, and aprolonged dissolution of aluminosilicates (seen in the high aluminum,silicon concentrations in the effluent), indicative of the simultaneousdissolution of clays and calcite. This simultaneous dissolution iscritical for the execution of a chelating agent/HF/Bronsted acid fluidas a simplified acid into a sandstone reservoir. Further, FIG. 7 shows a13% stimulation of the core permeability after treatment.

Example 7

A treatment fluid containing 50% by weight of DAE (45% active) and 1% byweight ammonium bifluoride (ABF) was used to treat a series of sandstonecore samples at about 178° F. (about 80° C.), and a fluid pH of about 5.The cores were higher in carbonate minerals (calcite and dolomite) thanBerea sandstone cores, as seen in Table 1. Sandstone mineralogies withhigher acid-soluble minerals (specifically carbonates) are capable ofefficient permeability stimulation at lower temperatures (<125° C.),though the reactivity of the higher-pH fluid toward certain minerals isdecreased at those temperatures. In the core experiments summarized inTable 2, the core initial permeabilities (k-mini) to 4% NH₄Cl (aq) weremeasured in the production direction; afterwards, 60 pore-volumes of thetreatment fluid was injected through the core in the injection directionfollowed by a 12-hour shut-in at temperature. Finally, the finalpermeability (k-fin) to 4% NH₄Cl (aq) was measured in the productiondirection. The results of the coreflood tests are summarized in Table 2,where the stimulation is measured as the ratio of the final-permeability(k-fin) to the initial permeability (k-ini). Though Table 1 indicatesthat all four cores are high in calcite (>30%), cores A4 and A5 showmore impressive stimulation ratios than cores T1 and T3. A possiblereason for this difference is in the lower initial permeabilities ofcores A4 and A5 (due to higher amounts of damaging minerals in theporosity) being easier to stimulate. This example demonstrates thathigh-pH solutions as described herein are effective in stimulation ofcertain mineralogies at lower temperatures.

TABLE 1 Mineralogy Summary Core Plagio- K- Cal- Py- Total ID Quartzclase Feldspar cite Dolomite rite Clays* A4 45 7 1 37 4 1 6 A5 43 9 1 344 1 8 T1 50 5 1 33 2 0 9 T3 47 5 1 38 1 1 8 *Total Clays = combinationof kaolinite, chlorite, illite, smectite, and mixed-layerillite/smectite

TABLE 2 Coreflood Summary Temperature Shut-In Flow Rate k-ini k-fin CoreID (° C.) (hours) (cc³/min) (mD) (mD) k-fin/k-ini A4 80 12 0.5 0.12 0.665.5 A5 80 12 0.5 0.08 1.09 13.6 T1 80 12 0.5 1.91 2.58 1.35 T3 80 12 1.50.81 0.98 1.21

While the invention has been shown in only some of its forms, it shouldbe apparent to those skilled in the art that it is not so limited, butis susceptible to various changes and modifications without departingfrom the scope of the invention. Accordingly, it is appropriate that theappended claims be construed broadly and in a manner consistent with thescope of the invention.

Although the methods have been described here for, and are mosttypically used for, hydrocarbon production, they may also be used ininjection wells and for production of other fluids, such as water orbrine. The particular embodiments disclosed above are illustrative only,as the invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details herein shown, other than as described in theclaims below. It is therefore evident that the particular embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the invention. Accordingly,the protection sought herein is as set forth in the claims below.

1. A method of treating a sandstone-containing formation penetrated by awellbore, the method comprising: forming a treatment fluid comprising anaqueous fluid containing a Bronsted acid, a hydrogen fluoride source andan organic acid or salt thereof that is substantially soluble in theaqueous fluid, the fluid containing less than about 2% of fluoride (F⁻)by weight of the fluid and from 2% or less of sodium (Na⁺) by weight ofthe fluid, wherein the treatment fluid has a pH of about 6 or less;introducing the treatment fluid into the formation through the wellboreas a single-stage without introducing an acid-containing fluid preflushinto the formation prior to introducing the treatment fluid; andshutting in the fluid into to the formation for about 2 hours or more,prior to flowing back the treatment fluid to the surface, wherein thecombination of Bronsted acid/organic acid or salt thereof is present inthe treatment fluid in an amount sufficient to keep at least 5000 ppmCa2+ in solution.
 2. The method of claim 1, wherein the organic acid orsalt thereof is a chelating agent.
 3. The method of claim 1, wherein theBronsted acid is selected from at least one of HCl, an organic acid, asulfamic acid, a sulfonic acid, a phosphoric acid, a phosphonic acid, anammonium salt, an ammine salt, a chelate acid and combinations thereof.4. The method of claim 1, wherein the organic acid or salt thereof is anammoniated chelate.
 5. The method of claim 1, wherein the organic acidor salt thereof is selected from at least one of ethylenediaminetetraacetic acid (EDTA), hydroxyethyl ethylenediamine triacetic acid(HEDTA), diethylene triamine pentaacetic acid (DTPA), 2-hydroxyethyliminodiacetic acid (HEIDA), citric acid, tartaric acid, succinic acid,lactic acid, oxalic acid, malic acid and maleic acid, polycarboxylates,homopolymers or copolymers of poly(acrylic acid) and poly(maleic acid)and the partial-ammonium or sodium salts thereof.
 6. The method of claim1, wherein the hydrogen fluoride source is selected from at least one ofhydrofluoric acid, ammonium fluoride, ammonium bifluoride, fluoroboricacid, hexafluorophosphoric acid, difluorophosphoric acid, fluorosulfonicacid, polyvinylammonium fluoride, polyvinylpyridinium fluoride,pyridinium fluoride, imidazolium fluoride, sodium tetrafluoroborate,ammonium tetrafluoroborate, salts of hexafluoroantimony,polytetrafluoroethylene polymers, and combinations of these.
 7. Themethod of claim 1, wherein the organic acid or salt thereof is presentin an amount of from about 5 to about 40% by weight of the treatmentfluid.
 8. The method of claim 1, wherein the treatment fluid isintroduced into the formation through the wellbore as a single-stagewithout introducing a brine-containing fluid preflush into the formationprior to introducing the treatment fluid.
 9. The method of claim 1,wherein the treatment fluid is used at a temperature of from 100° C. orless.
 10. A method of treating a sandstone-containing formationpenetrated by a wellbore, the method comprising: forming a treatmentfluid comprising an aqueous fluid containing a Bronsted acid, a hydrogenfluoride source and an organic acid or salt thereof that issubstantially soluble in the aqueous fluid, the fluid containing lessthan about 2% of fluorine (F−) by weight of the aqueous fluid and from2% or less of sodium (Na+), wherein the treatment fluid has a pH ofabout 6 or less; shutting in the fluid into to the formation for about 2hours or more prior to flowing back the treatment fluid to the surface;and wherein the treatment fluid is introduced as a single-stagetreatment without introducing a brine-containing or acid-containingfluid preflush into the formation prior to introducing the treatmentfluid, wherein the combination of Bronsted acid/organic acid or saltthereof is present in the treatment fluid in an amount sufficient tokeep at least 5000 ppm Ca2+ in solution.
 11. The method of claim 10,wherein the organic acid or salt thereof is a chelating agent.
 12. Themethod of claim 10, wherein the Bronsted acid is selected from at leastone of HCl, an organic acid, a sulfamic acid, a sulfonic acid, aphosphoric acid, a phosphonic acid, an ammonium salt, an ammine salt, achelate acid and combinations thereof.
 13. The method of claim 10,wherein the organic acid or salt thereof is an ammoniated chelate. 14.The method of claim 10, wherein the organic acid or salt thereof isselected from at least one of ethylenediamine tetraacetic acid (EDTA),hydroxyethyl ethylenediamine triacetic acid (HEDTA), diethylene triaminepentaacetic acid (DTPA), 2-hydroxyethyl iminodiacetic acid (HEIDA),citric acid, tartaric acid, succinic acid, lactic acid, oxalic acid,malic acid and maleic acid, polycarboxylates, homopolymers or copolymersof poly(acrylic acid) and poly(maleic acid) and the partial-ammonium orsodium salts thereof.
 15. The method of claim 10, wherein the treatmentfluid is used at a temperature of from 100° C. or less.
 16. The methodof claim 10, wherein the hydrogen fluoride source is selected from atleast one of hydrofluoric acid, ammonium fluoride, ammonium bifluoride,fluoroboric acid, hexafluorophosphoric acid, difluorophosphoric acid,fluorosulfonic acid, polyvinylammonium fluoride, polyvinylpyridiniumfluoride, pyridinium fluoride, imidazolium fluoride, sodiumtetrafluoroborate, ammonium tetrafluoroborate, salts ofhexafluoroantimony, polytetrafluoroethylene polymers, and combinationsof these.